The present invention relates to methods and compositions for use in industrial, oilfield, and/or subterranean operations. More particularly, the present invention relates to methods of reducing the viscosity of treatment fluids that comprise a gelling agent comprising a diutan composition, and utilizing breakers that comprise an acid composition.
Treatment fluids may be used in a variety of subterranean treatments, including, but not limited to, stimulation treatments, damage removal, formation isolation, wellbore cleanout, scale removal, scale control, drilling operations, cementing, conformance treatments, and sand control treatments. Treatment fluids may also be used in a variety of pipeline treatments. As used herein, the term “treatment,” or “treating,” refers to any operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
One common production stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. The treatment fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates, inter alia, may prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. The proppant particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid flow) through the fractures in which they reside. Once at least one fracture is created and the proppant particulates are substantially in place, the treatment fluid may be “broken” (i.e., the viscosity of the fluid is reduced), and the treatment fluid may be recovered from the formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In “gravel-packing” treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”), and deposits at least a portion of those particulates in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a “gravel pack,” which is a grouping of particulates that are packed sufficiently close together so as to prevent the passage of certain materials through the gravel pack. This “gravel pack” may, inter alia, enhance sand control in the subterranean formation and/or prevent the flow of particulates from an unconsolidated portion of the subterranean formation (e.g., a propped fracture) into a well bore. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation sand from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the well bore. The gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like, among other purposes, to enhance conductivity (e.g., fluid flow) through the gravel pack in which they reside. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “FracPac™ ” operations). In such “frac pack” operations, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
Maintaining sufficient viscosity in these treatment fluids is important for a number of reasons. Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important in acid treatments, in friction reduction and to control and/or reduce fluid loss into the formation. Moreover, a treatment fluid of a sufficient viscosity may be used to divert the flow of fluids present within a subterranean formation (e.g., formation fluids, other treatment fluids) to other portions of the formation, for example, by invading the higher permeability portions of the formation with a fluid that has high viscosity at low shear rates. At the same time, while maintaining sufficient viscosity of the treatment fluid often is desirable, it also may be desirable to reduce the viscosity at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
To provide the desired viscosity, polymeric gelling agents may be added to the treatment fluids. Examples of commonly used polymeric gelling agents include, but are not limited to, biopolymers, polysaccharides such as guar gums and derivatives thereof, cellulose derivatives, synthetic polymers, and the like. These gelling agents, when hydrated and at a sufficient concentration, are capable of forming a viscous solution. When used to make an aqueous-based viscosified treatment fluid, a gelling agent is combined with an aqueous fluid and the soluble portions of the gelling agent are dissolved in the aqueous fluid, thereby increasing the viscosity of the fluid. To further increase the viscosity of a treatment fluid, often the molecules of the gelling agent are “crosslinked” with the use of a crosslinking agent. Conventional crosslinking agents usually comprise a metal complex or compound that interacts with at least two polymer molecules to form a “crosslink” between them.
At some point in time, e.g., after a viscosified treatment fluid has performed its desired function, the viscosity of the viscosified treatment fluid should be decreased. This is often referred to as “breaking the gel” or “breaking the fluid.” This can occur by, inter alia, reversing the crosslink between crosslinked polymer molecules, breaking down the molecules of the polymeric gelling agent, or breaking the crosslinks between polymer molecules. The use of the term “break” herein incorporates at least all of these mechanisms. As used herein, the term “viscosified treatment fluid” refers to a treatment fluid that has had its viscosity increased by a diutan composition or any other means. Certain breakers that are capable of breaking viscosified treatment fluids comprising crosslinked gelling agents are known in art. For example, breakers comprising sodium bromate, sodium chlorite, sodium persulfate, ammonium persulfate, sodium hypochlorite, lithium hypochlorite, sodium perborate, and other oxidizing agents have been used to reduce the viscosity of treatment fluids comprising crosslinked polymers. Examples of such breakers are described in U.S. Pat. Nos. 5,759,964 to Shuchart, et al., and 5,413,178 to Walker, et al., the relevant disclosures of which are herein incorporated by reference.
While oxidizing agents may be effective to at least partially break treatment fluids comprising a diutan composition, the use of oxidizing breakers in combination with diutan may interfere with a subterranean formation's ability to regain a desired level of permeability. This may be due in part to residual treatment fluids or reaction products that remain in the formation after the treatment fluid is broken. In particular, it is believed that oxidizing agents may not substantially degrade or otherwise reduce the presence of diutan-producing bacterial bodies in the subterranean formation. These bacterial bodies are thought to be at least partially responsible for creating a physical barrier in the formation which reduces permeability. Additionally, the use of oxidizing agents to break treatment fluids comprising a diutan composition may be problematic at temperatures above about 200° F., because oxidizing breakers may degrade the treatment fluid too quickly for the treatment fluid to suspend proppant particulates for a desired length of time, e.g., the length of time necessary for the treatment fluid to transport the proppant particulates to a desired place in the formation. In particular, a treatment fluid that is gelled with diutan and contains an oxidizing breaker may not be able to adequately suspend particulates for a desired length of time, e.g. more than about two hours.